Every day, oil and gas companies are challenged to produce as much of their oil reserves as possible. During the primary recovery stage, reservoir drive comes from a number of natural mechanisms. These include natural water pushing oil towards the well, expansion of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil, and gravity drainage resulting from the movement of oil within the reservoir from the upper to the lower parts where the wells are located. Recovery factor during the primary recovery stage is typically about 5-15% under such natural drive mechanisms.
Over the lifetime of an oil well, however, the pressure will eventually fall, and at some point there will be insufficient underground pressure to force the oil to the surface. After natural reservoir drive diminishes, secondary and tertiary recovery methods are applied to further increase recovery.
Secondary recovery methods rely on the supply of external energy into the reservoir in the form of injecting fluids to increase reservoir pressure, hence replacing or increasing the natural reservoir drive with an artificial drive. In addition, pumps, such as beam pumps, gas lift assisted pumping, and electrical submersible pumps (ESPs), can be used to bring the oil to the surface. Secondary recovery techniques include increasing reservoir pressure by water injection, natural gas reinjection, and miscible injection with solvents such as CO2, the most common of which is probably water injection.
Carbon dioxide (CO2) flooding is a process whereby carbon dioxide is injected into an oil reservoir in order to increase output. When a reservoir's pressure is depleted through primary and secondary production, CO2 flooding can be an ideal tertiary recovery method. It is particularly effective in reservoirs deeper than 2,000 ft., where CO2 will be in a supercritical state (see FIG. 1), with API oil gravity greater than 20° and remaining oil saturations greater than 20%.
CO2 is injected into oil reservoirs because it dissolves into oil easily, reduces oil viscosity, and can extract the light components of crude oil at sufficiently high pressure. Further, CO2 can become miscible with oil at lower pressures than other gases, thus diluting the oil and making it more mobile.
If a well has been produced before and has been designated suitable for CO2 flooding, the first step is to restore the pressure within the reservoir to one suitable for production. This is usually done by injecting water, which restores pressure within the reservoir to a suitable pressure. Once the reservoir is pressurized, CO2 is injected into the same injection wells. The CO2 gas is forced into the reservoir to come into contact with the oil. This creates a miscible zone of diluted oil that can be moved more easily to the production well. See e.g., FIG. 2. The CO2 is also expected to reduce the pH of water in situ by 2-3 units, as CO2 dissolves in the water making carbonic acid. This often results in acidic conditions.
CO2 injection can be continuous, but is usually alternated with more water injections, so that the water acts to sweep the diluted oil towards the production zone, in a process known as Water-Alternating-Gas or “WAG.” Water injection alone tends to sweep the lower parts of a reservoir, while gas injected alone sweeps more of the upper parts of a reservoir owing to gravitational forces. Three-phase gas, oil and water flow is better at displacing residual oil in the pore system than two-phase flow. WAG and SWAG (Simultaneous WAG) thus improve the efficiency of both microscopic and macroscopic displacement. The Weyburn oil field in Saskatchewan is a famous example where this method was applied. At Weyburn, waste CO2 from a US industrial plant was used to give an additional 22×106 m3 (140 MMSTB) oil production and disposal of 19×106 tons (350 Bscf) of CO2.
However, the efficiency of various CO2 injection procedures is not as good as it could be due to the very low viscosity of CO2, which makes it easier to flow through high permeability zones and fractures—the so called “thief zones”—thus bypassing oil left behind in lower permeability zones.
Thief zones are usually blocked with polymers, foams, gels, and the like, thus forcing injection fluids through the less permeable zones. Gels produced with acrylamide-type polymers or xanthan gums have been used to block these fractures or high permeability streaks so subsequent fluids injected are diverted to the low permeability zones to improve sweep efficiency of CO2 floods.
Gelled foams have also been used to block fractures and diverting the flow of CO2 to lower permeability zones, improving sweep efficiency of CO2 floods and reducing the cost by 50%.
The use of a pH-sensitive biopolymer that gels under acidic conditions has also been proposed. Solutions of a polysaccharide named “KUSP1” (an unbranched 1→3 D-Glucan) were gelled when exposed to lower pH values created by an ester hydrolysis. Such solutions also gelled when exposed to CO2.
Gels produced with sulfomethylated resorcinol and formaldehyde tested in situ, reduce the permeability to CO2 by about 99%.
Solutions of crosslinked polyacrylic acid hydrogels with pH-sensitivity have also been suggested for mobility control. However, such hydrogels exhibit lower viscosity values at the acidic pH ranges typically observed with CO2 floods. As such, these systems are not expected to perform well under CO2 flood conditions. In fact, several polymers are less viscous at acidic pH. See e.g., FIG. 3 showing polyacrylamide, polyacrylic acid and various partially hydrolyzed polyacrylamides (PHPAM) at various pH's at 3 rpm in 0.5% brine.
Thus, what is needed in the art is a gel or polymer system that is easy to pump, yet becomes more viscous in situ, is resistant to washout, and is compatible with low pH and brine conditions.